Organizational Multi layered documentation frameworks, complex document writing styles, cross referencing, poor document integration, end user language barriers and psychological factors for searching relevant information under pressure complicates the understanding of a technical document. Complex technical documents intimidate the end user and shrinks the user understanding. Document engineering or Usability mapping of documents is proven scientific method for writing technical documents in a simplified and user-friendly manner. The document engineering concepts are based on human psychology, that helps the user to navigate through document content rather searching for specific keyword or information. Safety intensive industrial sectors such as Aviation industry, Oil and Gas are already adopting the document engineering concepts in their technical documentation. It is proven in many organizations that the usage of document engineering concepts simplifies the document complexity and the end users feel much comfort in understanding the documents in their work. In this paper an attempt has been made suggest adoptable user engineering concepts to simplify technical HSE documents. Also, the paper discusses some of the in-built hidden readability features in Microsoft word for checking reading ease and reading grade levels to improve simplification of documents. The paper discusses the psychological aspects behind document reading, understanding, cognitive linking for reaching the required information. Also, the paper discusses some of the best practices to be considered for technical document writers.
{"title":"Human Factors in HSE Performance – Role of User-Friendly HSE Documentation","authors":"Saud Mohamed Al Hammadi, Ramakrishna Akula","doi":"10.2118/207594-ms","DOIUrl":"https://doi.org/10.2118/207594-ms","url":null,"abstract":"\u0000 Organizational Multi layered documentation frameworks, complex document writing styles, cross referencing, poor document integration, end user language barriers and psychological factors for searching relevant information under pressure complicates the understanding of a technical document. Complex technical documents intimidate the end user and shrinks the user understanding. Document engineering or Usability mapping of documents is proven scientific method for writing technical documents in a simplified and user-friendly manner. The document engineering concepts are based on human psychology, that helps the user to navigate through document content rather searching for specific keyword or information. Safety intensive industrial sectors such as Aviation industry, Oil and Gas are already adopting the document engineering concepts in their technical documentation. It is proven in many organizations that the usage of document engineering concepts simplifies the document complexity and the end users feel much comfort in understanding the documents in their work.\u0000 In this paper an attempt has been made suggest adoptable user engineering concepts to simplify technical HSE documents. Also, the paper discusses some of the in-built hidden readability features in Microsoft word for checking reading ease and reading grade levels to improve simplification of documents. The paper discusses the psychological aspects behind document reading, understanding, cognitive linking for reaching the required information. Also, the paper discusses some of the best practices to be considered for technical document writers.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72938986","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Soliman, S. Salu, A. Al-Aiderous, Nisar Ahmad K. Ansari, Khamis Al-Hajri, Ellyes Mecikar
Keeping pace with the rest of the world on reducing the greenhouse gas emission, Saudi Aramco embarked on an aggressive program to minimize or cut routine flaring and energy resources used in producing oil and gas through policies, standards and inhouse innovations. The innovative Unconventional Waste & Flare Gas Recovery System UFGRS has supported the corporate strategy to minimize or eliminate routine flaring with minimum CAPEX and OPEX. This paper present in detail the innovative Ejector Based Unconventional Waste/Flare Gas Recovery System (UFGRS) without using gas compressors. The objective of the project is to eliminate the hydrocarbon gas release to atmosphere for any upset flameout scenario from GOSP-A massive flare & relief system and continuously recover 1.825 Billion Standard Cubic Feet per year (1.825 BSCFY) of valuable purge gas with the lowest CAPEX and OPEX. Conventional Flare Gas Recovery System (FGRS) using gas compressors is the normal choice deployed in many facilities to recover the routine gas flaring but it was found to have high CAPEX and OPEX (maintenance, high power consumption & labor intensive) compared to the value of the recovered gas. Also, the compressors based FGRS is more complex and less reliable than the ejector (static) based FGRS. In addition, the innovative FGRS is capable of handling high turndown ratios compared to convention compressor based FGRS. Also, additional innovative parts of this idea is the integration with the existing compression system and the use of only static equipment like ejectors, pipes, valves and water seal drums to recover the waste/flare gas. The idea has very low operating cost compared to conventional flare gas recovery systems, apart from significant gas savings. The unconventional FGRS system was proven successfully in December 2020. The system is currently in operation for 8 months without any interruption and managed to eliminate the total design routine gas flaring rate of 1.825 BSCFY GOSP-A producing facilities. Also, the project resulted in reducing CO2 emission by 106,000 ton/year which positively contributed to the kingdom circular economy initiatives. To further enhance the ejector based FGRS, a US Patent No. 10,429,067 was granted in October 2019 to utilize the Ejector based FGRS concept for Emergency flare gas recovery. The innovative idea includes utilizing multiple ejectors in parallel with provision of different ejectors operating at different pressures that will allow the system to be used to recover flare gas over a range of different flow rates corresponding to different emergency release scenarios. Also, two new patents are under filing to utilize the liquid as motive fluid instead of the gas.
{"title":"Unconventional Waste & Flare Gas Recovery System UFGRS in New Circular Economy","authors":"M. Soliman, S. Salu, A. Al-Aiderous, Nisar Ahmad K. Ansari, Khamis Al-Hajri, Ellyes Mecikar","doi":"10.2118/207956-ms","DOIUrl":"https://doi.org/10.2118/207956-ms","url":null,"abstract":"\u0000 Keeping pace with the rest of the world on reducing the greenhouse gas emission, Saudi Aramco embarked on an aggressive program to minimize or cut routine flaring and energy resources used in producing oil and gas through policies, standards and inhouse innovations. The innovative Unconventional Waste & Flare Gas Recovery System UFGRS has supported the corporate strategy to minimize or eliminate routine flaring with minimum CAPEX and OPEX.\u0000 This paper present in detail the innovative Ejector Based Unconventional Waste/Flare Gas Recovery System (UFGRS) without using gas compressors. The objective of the project is to eliminate the hydrocarbon gas release to atmosphere for any upset flameout scenario from GOSP-A massive flare & relief system and continuously recover 1.825 Billion Standard Cubic Feet per year (1.825 BSCFY) of valuable purge gas with the lowest CAPEX and OPEX.\u0000 Conventional Flare Gas Recovery System (FGRS) using gas compressors is the normal choice deployed in many facilities to recover the routine gas flaring but it was found to have high CAPEX and OPEX (maintenance, high power consumption & labor intensive) compared to the value of the recovered gas. Also, the compressors based FGRS is more complex and less reliable than the ejector (static) based FGRS. In addition, the innovative FGRS is capable of handling high turndown ratios compared to convention compressor based FGRS. Also, additional innovative parts of this idea is the integration with the existing compression system and the use of only static equipment like ejectors, pipes, valves and water seal drums to recover the waste/flare gas. The idea has very low operating cost compared to conventional flare gas recovery systems, apart from significant gas savings.\u0000 The unconventional FGRS system was proven successfully in December 2020. The system is currently in operation for 8 months without any interruption and managed to eliminate the total design routine gas flaring rate of 1.825 BSCFY GOSP-A producing facilities. Also, the project resulted in reducing CO2 emission by 106,000 ton/year which positively contributed to the kingdom circular economy initiatives.\u0000 To further enhance the ejector based FGRS, a US Patent No. 10,429,067 was granted in October 2019 to utilize the Ejector based FGRS concept for Emergency flare gas recovery. The innovative idea includes utilizing multiple ejectors in parallel with provision of different ejectors operating at different pressures that will allow the system to be used to recover flare gas over a range of different flow rates corresponding to different emergency release scenarios. Also, two new patents are under filing to utilize the liquid as motive fluid instead of the gas.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"142 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73318495","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. Xiao, Mingsheng Lv, Guang-Rong Hu, Wenyuan Tian, Li Wang, Ren Ma, Wenhao Zhao, Maryam R Al Shehhi, A. Shashanka
In Western UAE, the Middle Cretaceous petroleum system is composed of Shilaif source, Mishrif/Tuwayil reservoir and Tuwayil/Ruwaydha seal. Oil is discovered in Tuwayil sandstone in DH and NN fields. Well correlation of Tuwayil siliciclastic interval shows high heterogeneity and rapid lithology varies. Currently, a few general studies about Tuwayil sandstone was published. However, detailed sedimentary facies, reservoir characteristics and accumulation mechanism about Tuwayil are ambiguous. Limitation on these aspects prohibits enlarging exploration activity of Tuwayil and makes barriers to deepen understanding of the whole K2 PS. To enhance understanding on Tuwayil formation, well data in DH, NN fields and adjacent area was integrated. Dedicated single well analysis, well correlation and petrophysics study were carried out. Cores were observed and laboratory outcomes including TS, SEM, RCA, MICP, XRD were adopted into this study. Furthermore, we have also utilized 2D&3D seismic to illustrate the spatial distribution of Tuwayil siliciclastic setting and interior sediment pattern. Basically, the Tuwayil sand-shale interval represents the infilling of Mishrif/Shilaif intrashelf basin and mainly deposits in the tidal flat-delta facies. The epi-continental clast is sourced from the Arabian shield and transferred from west to east. In Western UAE, the Tuwayil depocenter located in DH field, where 4-5 sand layers deposit with net pay of 30-40ft. In NN field, only one sand layer develops with net pay about 4-6ft. Through deposition cycles identification and seismic reflection observation, two sand groups could be recognized in this interval. The lower group is constrained in the depocenter and influenced by the paleo-geomorphology background. The upper group overpassed the former set and pinched out around north of NN. The Mishrif/Shilaif slope area is another potential belt to enlarge Tuwayil discovery, where stratigraphic onlap could be observed and it probably represents the sand pinch-out in lower sand group. For the K2 PS, previous study believed the shale between Tuwayil sand and Mishrif separate these two reservoirs and works as cap rock for Mishrif grainstone. This study suggests that this shale is too thin and not continuous enough to hold the hydrocarbon in Mishrif. On that note, Tuwayil sand and Mishrif belong to the same petroleum system in NN and may have the same OWC. In the NN field, it is quite crucial to consider the extension of Tuwayil sand during evaluating the stratigraphic prospect of Mishrif because the hydrocarbon is mostly likely charged Tuwayil sand first and then gets into underlain Mishrif. This study provides updates and understandings on sedimentary facies, depositional pattern, hydrocarbon accumulation mechanism, reservoir extension and potential identification of Tuwayil formation, which has inspiring implications for the whole K2 PS and could also de-risk the further exploration activity in Western UAE.
{"title":"Characteristic of Tuwayil Formation and New Insight into its Contribution in Middle Cretaceous Petroleum System, Western UAE","authors":"D. Xiao, Mingsheng Lv, Guang-Rong Hu, Wenyuan Tian, Li Wang, Ren Ma, Wenhao Zhao, Maryam R Al Shehhi, A. Shashanka","doi":"10.2118/207521-ms","DOIUrl":"https://doi.org/10.2118/207521-ms","url":null,"abstract":"\u0000 In Western UAE, the Middle Cretaceous petroleum system is composed of Shilaif source, Mishrif/Tuwayil reservoir and Tuwayil/Ruwaydha seal. Oil is discovered in Tuwayil sandstone in DH and NN fields. Well correlation of Tuwayil siliciclastic interval shows high heterogeneity and rapid lithology varies. Currently, a few general studies about Tuwayil sandstone was published. However, detailed sedimentary facies, reservoir characteristics and accumulation mechanism about Tuwayil are ambiguous. Limitation on these aspects prohibits enlarging exploration activity of Tuwayil and makes barriers to deepen understanding of the whole K2 PS.\u0000 To enhance understanding on Tuwayil formation, well data in DH, NN fields and adjacent area was integrated. Dedicated single well analysis, well correlation and petrophysics study were carried out. Cores were observed and laboratory outcomes including TS, SEM, RCA, MICP, XRD were adopted into this study. Furthermore, we have also utilized 2D&3D seismic to illustrate the spatial distribution of Tuwayil siliciclastic setting and interior sediment pattern.\u0000 Basically, the Tuwayil sand-shale interval represents the infilling of Mishrif/Shilaif intrashelf basin and mainly deposits in the tidal flat-delta facies. The epi-continental clast is sourced from the Arabian shield and transferred from west to east. In Western UAE, the Tuwayil depocenter located in DH field, where 4-5 sand layers deposit with net pay of 30-40ft. In NN field, only one sand layer develops with net pay about 4-6ft. Through deposition cycles identification and seismic reflection observation, two sand groups could be recognized in this interval. The lower group is constrained in the depocenter and influenced by the paleo-geomorphology background. The upper group overpassed the former set and pinched out around north of NN. The Mishrif/Shilaif slope area is another potential belt to enlarge Tuwayil discovery, where stratigraphic onlap could be observed and it probably represents the sand pinch-out in lower sand group.\u0000 For the K2 PS, previous study believed the shale between Tuwayil sand and Mishrif separate these two reservoirs and works as cap rock for Mishrif grainstone. This study suggests that this shale is too thin and not continuous enough to hold the hydrocarbon in Mishrif. On that note, Tuwayil sand and Mishrif belong to the same petroleum system in NN and may have the same OWC. In the NN field, it is quite crucial to consider the extension of Tuwayil sand during evaluating the stratigraphic prospect of Mishrif because the hydrocarbon is mostly likely charged Tuwayil sand first and then gets into underlain Mishrif.\u0000 This study provides updates and understandings on sedimentary facies, depositional pattern, hydrocarbon accumulation mechanism, reservoir extension and potential identification of Tuwayil formation, which has inspiring implications for the whole K2 PS and could also de-risk the further exploration activity in Western UAE.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75650278","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Pollio, Gianluca Fortunato, Salvatore Spagnolo, Gianni Baldassarri, P. Cappuccio, V. Mittiga, R. Cherri, M. Colombo, Salvatore Privitera, Riccardo Caldarelli, M. Ridenti, Y. Santin, J. Vasquez, Danilo Appicciutoli
Water production has always afflicted mature fields due to the uneconomical nature of high water cut (WC) wells and the high cost of water management. Rigless coiled tubing (CT) interventions with increasingly articulated operating procedures are the key to a successful water reduction. In the scenario presented in this paper, high technological through tubing water shut off (WSO) for a long horizontal open hole (OH) well in a naturally fractured carbonate reservoir leads the way to new opportunities of production optimization. Engineering phase included sealant fluid re-design: the peculiar well architecture and fracture systems led to the customization of a sealant gel by modifying its rheological properties through laboratory tests, to improve effectiveness of worksite operations. A new ad-hoc procedure was defined, with a new selective pumping and testing technique tailored to each drain fracture. The use of Real-Time Hybrid Coiled Tubing Services (CT with fiber optic system coupled with real time capabilities of an electric cable) made it possible to optimize intervention reliability. Details of the operating procedure are given, with the aim of ensuring a successful outcome of the overall treatment Sealing gels are effective in plugging the formation, but in fractured environments the risk of losing the product before it starts to build viscosity is high. The success of the water shut off job has been obtained by using specific gel with thixotropic properties for an effective placement. In addition, the pumping has been performed in steps, each followed by a pressure test to assess the effectiveness of the plugging. Results are compared to two past interventions with equal scope in the same well: a first one with high volume of gel and an unoptimized pumping technique through CT and a second where a water reactive product was pumped by bullheading. The selective and repetitive approach pumping multiple batches of sealant system with CT stationary in front of a single fracture provided the best results from all three techniques. The real-time bottom hole data reading capability provided by hybrid CT allowed the placement of thru tubing bridge plugs (BP) with high accuracy and confidence with the ability to set electrically, therefore reducing risks related to hydraulic setting tools (i.e. premature setting). This also allows continual pumping during the run in hole (RIH) to clean up the zone prior to setting the BP. The combination of this innovative pumping technique and customization of the sealant fluid made it possible to achieve unprecedented water reduction in the field. The high technology CT supported the operation by providing continuous power and telemetry to the bottom hole assembly (BHA) for real time (RT) downhole diagnostics. Moreover, the operating procedures offer basic guidelines to successfully perform water shut off jobs in any other reservoir independent of its geological nature and structure.
{"title":"Successful Zonal Isolation in Complex Fractured Carbonate Scenario Using Thixotropic Gel and Hybrid Electric-Fiber Cable Coiled Tubing Technology","authors":"P. Pollio, Gianluca Fortunato, Salvatore Spagnolo, Gianni Baldassarri, P. Cappuccio, V. Mittiga, R. Cherri, M. Colombo, Salvatore Privitera, Riccardo Caldarelli, M. Ridenti, Y. Santin, J. Vasquez, Danilo Appicciutoli","doi":"10.2118/207447-ms","DOIUrl":"https://doi.org/10.2118/207447-ms","url":null,"abstract":"\u0000 Water production has always afflicted mature fields due to the uneconomical nature of high water cut (WC) wells and the high cost of water management. Rigless coiled tubing (CT) interventions with increasingly articulated operating procedures are the key to a successful water reduction. In the scenario presented in this paper, high technological through tubing water shut off (WSO) for a long horizontal open hole (OH) well in a naturally fractured carbonate reservoir leads the way to new opportunities of production optimization.\u0000 Engineering phase included sealant fluid re-design: the peculiar well architecture and fracture systems led to the customization of a sealant gel by modifying its rheological properties through laboratory tests, to improve effectiveness of worksite operations.\u0000 A new ad-hoc procedure was defined, with a new selective pumping and testing technique tailored to each drain fracture.\u0000 The use of Real-Time Hybrid Coiled Tubing Services (CT with fiber optic system coupled with real time capabilities of an electric cable) made it possible to optimize intervention reliability.\u0000 Details of the operating procedure are given, with the aim of ensuring a successful outcome of the overall treatment\u0000 Sealing gels are effective in plugging the formation, but in fractured environments the risk of losing the product before it starts to build viscosity is high.\u0000 The success of the water shut off job has been obtained by using specific gel with thixotropic properties for an effective placement.\u0000 In addition, the pumping has been performed in steps, each followed by a pressure test to assess the effectiveness of the plugging.\u0000 Results are compared to two past interventions with equal scope in the same well: a first one with high volume of gel and an unoptimized pumping technique through CT and a second where a water reactive product was pumped by bullheading.\u0000 The selective and repetitive approach pumping multiple batches of sealant system with CT stationary in front of a single fracture provided the best results from all three techniques.\u0000 The real-time bottom hole data reading capability provided by hybrid CT allowed the placement of thru tubing bridge plugs (BP) with high accuracy and confidence with the ability to set electrically, therefore reducing risks related to hydraulic setting tools (i.e. premature setting). This also allows continual pumping during the run in hole (RIH) to clean up the zone prior to setting the BP.\u0000 The combination of this innovative pumping technique and customization of the sealant fluid made it possible to achieve unprecedented water reduction in the field.\u0000 The high technology CT supported the operation by providing continuous power and telemetry to the bottom hole assembly (BHA) for real time (RT) downhole diagnostics.\u0000 Moreover, the operating procedures offer basic guidelines to successfully perform water shut off jobs in any other reservoir independent of its geological nature and structure.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"4 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74523331","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Lina Song, Hongcheng Xu, Qiqi Wanyan, W. Liao, Shijie Zhang, Lei Shi, Kai Zhao
Inventory verification is one of vital tasks in underground gas storage (UGS) management process. For one reason, it is possible to know exactly how much natural gas is actually in the gas storage and ensure that it can be produced and supplied to the market in winter season when needed. For another, possible natural gas leakage can be discovered in time by inventory verification, to ensure the safe and economic operation of the gas storage. HTB UGS is a gas storage facility rebuilt from a depleted gas reservoir in China, which has been commissioning in June 2013. After 7 years injection-withdrawal cycles, we calculated and analyzed the inventory of this gas storage. First and foremost, we analyzed the data of 13 observation wells, including monitoring of gas-water interface, caprocks, and faults of the HTB UGS. In addition, we carried out core experiments in the laboratory to simulate the multi-cycle injection and withdrawal of gas storage, and analyzed the microscopic pore seepage characteristics of the reservoir during the UGS operation. Next, based on the operating pressure test data of the gas storage, we corrected the formation pressure and calculated the effective inventory. Furthermore, combined with the simulation results that we have carried out in the previous period, the effective inventory of HTB UGS was comprehensively evaluated. The result shows that: 1) The complete monitoring system indicates that the HTB UGS has no gas escaping from the storage field through faults, caprocks or wellbore. 2) The experimental result shows that in the process of gas withdrawal, various forms of natural gas such as jams and bypasses in some areas of the reservoir cannot participate in the flow, leading to this part of natural gas cannot be used. 3) Inventory calculation shows that as of the end of gas withdrawal in March 2020, the book inventory of HTB UGS is 99.8×108m3，while the effective inventory is 91.8×108m3 and the working gas is 39.9×108m3. 4) By acidification or other measures to improve the geological conditions, intensifying the well pattern and extending the gas production time, HTB UGS can increase its effective inventory. With the great efforts in constructing underground gas storage in China and the market-oriented operation of UGS, inventory verification of gas storage will become increasingly important. The inventory analysis method established in this article can provide a certain reference.
{"title":"Inventory Verification in Underground Gas Storage Rebuilt from Depleted Gas Reservoir: A Case Study from China","authors":"Lina Song, Hongcheng Xu, Qiqi Wanyan, W. Liao, Shijie Zhang, Lei Shi, Kai Zhao","doi":"10.2118/208134-ms","DOIUrl":"https://doi.org/10.2118/208134-ms","url":null,"abstract":"\u0000 Inventory verification is one of vital tasks in underground gas storage (UGS) management process. For one reason, it is possible to know exactly how much natural gas is actually in the gas storage and ensure that it can be produced and supplied to the market in winter season when needed. For another, possible natural gas leakage can be discovered in time by inventory verification, to ensure the safe and economic operation of the gas storage. HTB UGS is a gas storage facility rebuilt from a depleted gas reservoir in China, which has been commissioning in June 2013. After 7 years injection-withdrawal cycles, we calculated and analyzed the inventory of this gas storage.\u0000 First and foremost, we analyzed the data of 13 observation wells, including monitoring of gas-water interface, caprocks, and faults of the HTB UGS. In addition, we carried out core experiments in the laboratory to simulate the multi-cycle injection and withdrawal of gas storage, and analyzed the microscopic pore seepage characteristics of the reservoir during the UGS operation. Next, based on the operating pressure test data of the gas storage, we corrected the formation pressure and calculated the effective inventory. Furthermore, combined with the simulation results that we have carried out in the previous period, the effective inventory of HTB UGS was comprehensively evaluated.\u0000 The result shows that: 1) The complete monitoring system indicates that the HTB UGS has no gas escaping from the storage field through faults, caprocks or wellbore. 2) The experimental result shows that in the process of gas withdrawal, various forms of natural gas such as jams and bypasses in some areas of the reservoir cannot participate in the flow, leading to this part of natural gas cannot be used. 3) Inventory calculation shows that as of the end of gas withdrawal in March 2020, the book inventory of HTB UGS is 99.8×108m3，while the effective inventory is 91.8×108m3 and the working gas is 39.9×108m3. 4) By acidification or other measures to improve the geological conditions, intensifying the well pattern and extending the gas production time, HTB UGS can increase its effective inventory.\u0000 With the great efforts in constructing underground gas storage in China and the market-oriented operation of UGS, inventory verification of gas storage will become increasingly important. The inventory analysis method established in this article can provide a certain reference.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76588987","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
N. Zhou, Meng Lu, Fu-Chen Liu, Wenhong Li, Jianshen Li, S. Vaughan, Eric Trine, Zhitao Li, Matt Dean, Christopher Britton
Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding. Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions. Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs. In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.
{"title":"Development of the Surfactant-Based Chemical EOR Formula for Low Permeability Reservoirs","authors":"N. Zhou, Meng Lu, Fu-Chen Liu, Wenhong Li, Jianshen Li, S. Vaughan, Eric Trine, Zhitao Li, Matt Dean, Christopher Britton","doi":"10.2118/207969-ms","DOIUrl":"https://doi.org/10.2118/207969-ms","url":null,"abstract":"\u0000 Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding.\u0000 Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions.\u0000 Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs.\u0000 In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81599767","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Kamlesh Kumar, T. Narwal, Z. Alias, P. Agrawal, Ali Farsi, N. Hinai, Zahir Abri, Aiman Quraini, A. Hadhrami
South Oman has several pre-Cambrian reservoirs that are highly pressured (400-1000 bar), deep (3-5 km) and critically sour (H2S up to 10%). The combined STOIIP of these reservoirs makes it one of the largest gas EOR projects in the world. The objective here is to highlight the key performance indicators and digitalization techniques used for continuous and effective well, reservoir and facility management (WRFM) and production optimization, while honoring the facility constraints and gas export requirements. Real time pressure data such as tubing head pressures, injection/production rates along with other data including maps, static pressures and production logs are used to define an appropriate set of performance metric at various levels, e.g. reservoir, sector or well. Digitalization of surveillance data helps in real time production optimization such as offtake management based on creaming curves according to gas sink availability and facility constraints. Key business performance indicators include gas utilization efficiency; MGI performance indicators include incremental oil, throughput, instantaneous and cumulative voidage replacement ratios, gas breakthrough level and time, ratio of reservoir pressure to the target minimum miscibility pressure; and facility constraints are optimized through gas balance, along with tracking field performance against the initial FDP forecasts. Real time performance data is tracked using a commercial Real-Time Data Analysis tool (RTDA) and Database Analytics Visualization Tool (DAVT), with surveillance indicators targeted at well, reservoir and facility level. The above-defined Key Performance Indicators (KPI) are tracked against predictions from the field development plan in web-based portal developed at PDO (Nibras). Digitalization has enabled quick and effective monitoring of these KPI, short-term optimization of injection distribution and offtake rates to maximize oil production and overall value within facilities constraints and varying export gas commitments based on South Oman Gas Line (SOGL) network optimization. Using dimensionless plots and a standardized set of parameters help in developing a common understanding and benchmarking the MGI reservoir response with analogs and amongst different reservoirs. This work presents a set of performance KPIs and short-term optimization methodology using digitalization and LEAN framework that are tracked in a web-based portal, RTDA and DAVT. It provides means to facilitate offtake decisions to meet variable export requirements while honoring facilities constraints, assess reservoir performance, providing valuable insights that helps in speedy reservoir management decisions. This process has been replicated across PDO for all related MGI projects and can benefit other development types, e.g. chemical/steam injection.
{"title":"Digitalization for Effective Performance Management Using Key Performance Indicators in Miscible Gas Injection Projects in South Oman","authors":"Kamlesh Kumar, T. Narwal, Z. Alias, P. Agrawal, Ali Farsi, N. Hinai, Zahir Abri, Aiman Quraini, A. Hadhrami","doi":"10.2118/207917-ms","DOIUrl":"https://doi.org/10.2118/207917-ms","url":null,"abstract":"\u0000 South Oman has several pre-Cambrian reservoirs that are highly pressured (400-1000 bar), deep (3-5 km) and critically sour (H2S up to 10%). The combined STOIIP of these reservoirs makes it one of the largest gas EOR projects in the world. The objective here is to highlight the key performance indicators and digitalization techniques used for continuous and effective well, reservoir and facility management (WRFM) and production optimization, while honoring the facility constraints and gas export requirements.\u0000 Real time pressure data such as tubing head pressures, injection/production rates along with other data including maps, static pressures and production logs are used to define an appropriate set of performance metric at various levels, e.g. reservoir, sector or well. Digitalization of surveillance data helps in real time production optimization such as offtake management based on creaming curves according to gas sink availability and facility constraints. Key business performance indicators include gas utilization efficiency; MGI performance indicators include incremental oil, throughput, instantaneous and cumulative voidage replacement ratios, gas breakthrough level and time, ratio of reservoir pressure to the target minimum miscibility pressure; and facility constraints are optimized through gas balance, along with tracking field performance against the initial FDP forecasts.\u0000 Real time performance data is tracked using a commercial Real-Time Data Analysis tool (RTDA) and Database Analytics Visualization Tool (DAVT), with surveillance indicators targeted at well, reservoir and facility level. The above-defined Key Performance Indicators (KPI) are tracked against predictions from the field development plan in web-based portal developed at PDO (Nibras). Digitalization has enabled quick and effective monitoring of these KPI, short-term optimization of injection distribution and offtake rates to maximize oil production and overall value within facilities constraints and varying export gas commitments based on South Oman Gas Line (SOGL) network optimization. Using dimensionless plots and a standardized set of parameters help in developing a common understanding and benchmarking the MGI reservoir response with analogs and amongst different reservoirs.\u0000 This work presents a set of performance KPIs and short-term optimization methodology using digitalization and LEAN framework that are tracked in a web-based portal, RTDA and DAVT. It provides means to facilitate offtake decisions to meet variable export requirements while honoring facilities constraints, assess reservoir performance, providing valuable insights that helps in speedy reservoir management decisions. This process has been replicated across PDO for all related MGI projects and can benefit other development types, e.g. chemical/steam injection.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"142 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77352238","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Hydrates formation in subsea pipelines is one of the main reliability concerns for flow assurance engineers. A fast and reliable assessment of the Cool-Down Time (CDT), the period between a shut-down event and possible hydrates formation in the asset, is of key importance for the safety of operations. Existing methods for the CDT prediction are highly dependent on the use of very complex physics-based models that demand large computational time, which hinders their usage in an online environment. Therefore, this work presents a novel methodology for the development of surrogate models that predict, in a fast and accurate way, the CDT in subsea pipelines after unplanned shutdowns. The proposed methodology is, innovatively, tailored on the basis of reliability perspective, by treating the CDT as a risk index, where a critic CDT threshold (i.e. the minimum time needed by the operator to preserve the line from hydrates formation) is considered to distinguish the simulation outputs into high-risk and low-risk domains. The methodology relies on the development of a hybrid Machine Learning (ML) based model using datasets generated through complex physics-based model’ simulations. The hybrid ML-based model consists of a Support Vector Machine (SVM) classifier that assigns a risk level (high or low) to the measured operating condition of the asset, and two Artificial Neural Networks (ANNs) for predicting the CDT at the high-risk (low CDT) or the low-risk (high CDT) operating conditions previously assigned by the classifier. The effectiveness of the proposed methodology is validated by its application to a case study involving a pipeline in an offshore western African asset, modelled by a transient physics-based commercial software. The results show outperformance of the capabilities of the proposed hybrid ML-based model (i.e., SVM + 2 ANNs) compared to the classical approach (i.e. modelling the entire system with one global ANN) in terms of enhancing the prediction of the CDT during the high-risk conditions of the asset. This behaviour is confirmed applying the novel methodology to training datasets of different size. In fact, the high-risk Normalized Root Mean Square Error (NRMSE) is reduced on average of 15% compared to the NRMSE of a global ANN model. Moreover, it’s shown that high-risk CDT are better predicted by the hybrid model even if the critic CDT, which divides the simulation outputs in high-risk and low-risk values (i.e. the minimum time needed by the operator to preserve the line from hydrates formation), changes. The enhancement, in this case, is on average of 14.6%. Eventually, results show how the novel methodology cuts down by more than one hundred seventy-eight times the computational times for online CDT predictions compared to the physics-based model.
{"title":"Artificial Intelligence for the Online Prediction of the Cool-down Time in a Subsea Pipeline After an Unplanned Shutdown","authors":"A. Gerri, A. Shokry, E. Zio, M. Montini","doi":"10.2118/208219-ms","DOIUrl":"https://doi.org/10.2118/208219-ms","url":null,"abstract":"\u0000 Hydrates formation in subsea pipelines is one of the main reliability concerns for flow assurance engineers. A fast and reliable assessment of the Cool-Down Time (CDT), the period between a shut-down event and possible hydrates formation in the asset, is of key importance for the safety of operations. Existing methods for the CDT prediction are highly dependent on the use of very complex physics-based models that demand large computational time, which hinders their usage in an online environment. Therefore, this work presents a novel methodology for the development of surrogate models that predict, in a fast and accurate way, the CDT in subsea pipelines after unplanned shutdowns. The proposed methodology is, innovatively, tailored on the basis of reliability perspective, by treating the CDT as a risk index, where a critic CDT threshold (i.e. the minimum time needed by the operator to preserve the line from hydrates formation) is considered to distinguish the simulation outputs into high-risk and low-risk domains.\u0000 The methodology relies on the development of a hybrid Machine Learning (ML) based model using datasets generated through complex physics-based model’ simulations. The hybrid ML-based model consists of a Support Vector Machine (SVM) classifier that assigns a risk level (high or low) to the measured operating condition of the asset, and two Artificial Neural Networks (ANNs) for predicting the CDT at the high-risk (low CDT) or the low-risk (high CDT) operating conditions previously assigned by the classifier.\u0000 The effectiveness of the proposed methodology is validated by its application to a case study involving a pipeline in an offshore western African asset, modelled by a transient physics-based commercial software. The results show outperformance of the capabilities of the proposed hybrid ML-based model (i.e., SVM + 2 ANNs) compared to the classical approach (i.e. modelling the entire system with one global ANN) in terms of enhancing the prediction of the CDT during the high-risk conditions of the asset.\u0000 This behaviour is confirmed applying the novel methodology to training datasets of different size. In fact, the high-risk Normalized Root Mean Square Error (NRMSE) is reduced on average of 15% compared to the NRMSE of a global ANN model. Moreover, it’s shown that high-risk CDT are better predicted by the hybrid model even if the critic CDT, which divides the simulation outputs in high-risk and low-risk values (i.e. the minimum time needed by the operator to preserve the line from hydrates formation), changes. The enhancement, in this case, is on average of 14.6%. Eventually, results show how the novel methodology cuts down by more than one hundred seventy-eight times the computational times for online CDT predictions compared to the physics-based model.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85644878","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Yibal Khuff project is a mixed oil-rims, associated gas, and non-associated gas development in highly fractured tight carbonate reservoirs. Rock types and fractures vary widely with significant contribution to flow. In the east segment of the field, 22 horizontal oil producers targeting K2 reservoir have been pre-drilled and tested extensively. The integration of well logs, borehole image data (BHI), well test data and production logs provide key insights into reservoir productivity and the development of a robust well and reservoir management plan, ready for start-up of the field in 2021. A log-based approach was used to classify the reservoir into three main rock types (RRT). Fractures were classified, and high impact fractures were identified. Reservoir flow profile based on noise and temperature logs was established and used in combination with fracture data and cement bond logs in understanding flow conformance and behind casing flow. A large variation in productivity index has been observed, from tight to highly productive wells. Different ways have been explored to establish the link between productivity index, fracture production, and matrix production by rock types. This is the first full field development in the Khuff formation in Sultanate of Oman. The results will benefit a wider audience. A holistic approach was taken to explore the link between well deliverability and nature of a complex geology. The outcome is a robust operating envelope and well, reservoir and facilities management (WRFM) plan, clearly driven by understanding of subsurface risk and opportunities.
{"title":"Insights into Khuff Oil Rim Development in Sultanate of Oman from Extensive Drilling and Well Testing Operations","authors":"Tingting Zhang, Arun Kumar, Rashid Al Maskari, Maryam Musalami, Sumaiya Habsi","doi":"10.2118/208139-ms","DOIUrl":"https://doi.org/10.2118/208139-ms","url":null,"abstract":"\u0000 The Yibal Khuff project is a mixed oil-rims, associated gas, and non-associated gas development in highly fractured tight carbonate reservoirs. Rock types and fractures vary widely with significant contribution to flow. In the east segment of the field, 22 horizontal oil producers targeting K2 reservoir have been pre-drilled and tested extensively. The integration of well logs, borehole image data (BHI), well test data and production logs provide key insights into reservoir productivity and the development of a robust well and reservoir management plan, ready for start-up of the field in 2021.\u0000 A log-based approach was used to classify the reservoir into three main rock types (RRT). Fractures were classified, and high impact fractures were identified. Reservoir flow profile based on noise and temperature logs was established and used in combination with fracture data and cement bond logs in understanding flow conformance and behind casing flow. A large variation in productivity index has been observed, from tight to highly productive wells. Different ways have been explored to establish the link between productivity index, fracture production, and matrix production by rock types.\u0000 This is the first full field development in the Khuff formation in Sultanate of Oman. The results will benefit a wider audience. A holistic approach was taken to explore the link between well deliverability and nature of a complex geology. The outcome is a robust operating envelope and well, reservoir and facilities management (WRFM) plan, clearly driven by understanding of subsurface risk and opportunities.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80064821","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
O. Maulidani, Pedro Escalona, Monica Paredes, M. Sierra, C. Bonilla, J. Villalobos, L. Bravo, D. Estevez, Alexander Pineda, Edgar Chicango, Geovanny Ramos, R. Rodríguez, Luis Alabuela, C. Freire, J. Guaman
The Covid-19 pandemic is an unprecedented condition to the global economy including the oil & gas industry. The ability to adapt to the imposed changes, requires creativity, innovation, digitalization of processes, and resilience. This work will show a novel integrated approach around four pillars which had improved operation efficiency and brought monetary value during a challenging 2020 in Shushufindi field, Ecuador. The first pillar is new technology adoption. This aims to extend run life of critical equipment resulting in a higher well productive time. Examples of adopted technology: Chrome-enrich tubulars, downhole microcaps chemical deployment, de-sander and multiphase/extended gas handler. The second pillar is the P3 process (Pre-Pulling-Post) to quickly and effectively find the root cause of well failure that leads to definite remedial action. Digital enabler is the third pillar, its value come from reducing operational downtime and risk by using real-time surveillance capability, remote control, and data intelligence. The final pillar is to re-establish an effective communication with all stakeholders. Various dashboards have been developed in order to provide the big picture of actual field condition in quickly manner as well as implementation of ESP real time surveillance & diagnostics, real time multiphase production test, and chemical treatment automation. Workshops, online technical, and service quality meetings are regularly conducted to ensure that recommendations and opportunities can be executed properly including contractual negotiations to enable new technology implementation. Despite all the restrictions during covid-19 pandemic and some force majeures in 2020, this integrated and digitalized approach has resulted an outstanding outcome: Well failure index reduced from 0.62 in 2019 to 0.41 in 2020; Production deferment related to well failure declined significantly from 2,420 bopd in 2019 to 1,259 bopd in 2020, which translate in savings of $16.8 million dollars. In addition to that, there was a reduction on operational cost from $26.3 million dollars in 2019 to $15.2 million dollars in 2020. This proven initiative has been supported and recognized by all stakeholders. Some new technologies and digitalization projects are in the process to be implemented in Shushufindi field as part of Ecuador digital strategy 2022. This successful integrated and digitalized approach can be adopted in other fields and will generate a huge business impact.
{"title":"An Integrated and Digitalized Approach to Reduce the Well Failure Index During Covid-19 Global Pandemic in Shushufindi Field","authors":"O. Maulidani, Pedro Escalona, Monica Paredes, M. Sierra, C. Bonilla, J. Villalobos, L. Bravo, D. Estevez, Alexander Pineda, Edgar Chicango, Geovanny Ramos, R. Rodríguez, Luis Alabuela, C. Freire, J. Guaman","doi":"10.2118/208028-ms","DOIUrl":"https://doi.org/10.2118/208028-ms","url":null,"abstract":"\u0000 The Covid-19 pandemic is an unprecedented condition to the global economy including the oil & gas industry. The ability to adapt to the imposed changes, requires creativity, innovation, digitalization of processes, and resilience. This work will show a novel integrated approach around four pillars which had improved operation efficiency and brought monetary value during a challenging 2020 in Shushufindi field, Ecuador.\u0000 The first pillar is new technology adoption. This aims to extend run life of critical equipment resulting in a higher well productive time. Examples of adopted technology: Chrome-enrich tubulars, downhole microcaps chemical deployment, de-sander and multiphase/extended gas handler. The second pillar is the P3 process (Pre-Pulling-Post) to quickly and effectively find the root cause of well failure that leads to definite remedial action. Digital enabler is the third pillar, its value come from reducing operational downtime and risk by using real-time surveillance capability, remote control, and data intelligence. The final pillar is to re-establish an effective communication with all stakeholders.\u0000 Various dashboards have been developed in order to provide the big picture of actual field condition in quickly manner as well as implementation of ESP real time surveillance & diagnostics, real time multiphase production test, and chemical treatment automation. Workshops, online technical, and service quality meetings are regularly conducted to ensure that recommendations and opportunities can be executed properly including contractual negotiations to enable new technology implementation.\u0000 Despite all the restrictions during covid-19 pandemic and some force majeures in 2020, this integrated and digitalized approach has resulted an outstanding outcome: Well failure index reduced from 0.62 in 2019 to 0.41 in 2020; Production deferment related to well failure declined significantly from 2,420 bopd in 2019 to 1,259 bopd in 2020, which translate in savings of $16.8 million dollars. In addition to that, there was a reduction on operational cost from $26.3 million dollars in 2019 to $15.2 million dollars in 2020.\u0000 This proven initiative has been supported and recognized by all stakeholders. Some new technologies and digitalization projects are in the process to be implemented in Shushufindi field as part of Ecuador digital strategy 2022. This successful integrated and digitalized approach can be adopted in other fields and will generate a huge business impact.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80135243","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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